1. Field of the Disclosure
The present disclosure relates generally to a downhole tool for use in oil and gas wells, and more specifically, to a tubing deployed ball seat and the method for fracturing a well formation using the tubing deployed ball seat.
2. Description of the Related Art
If a hydrocarbon well is not adequately producing, it may be necessary to perform a completion process on the formation to stimulate a production zone, such as hydraulic fracturing the production zone. Hydraulic fracturing is typically employed to create additional passageways or otherwise increase the permeability of underground rock formations to facilitate flow through the formation to a producing well. Typically, fracturing may be accomplished by injecting a fluid containing sand or other proppant under sufficient pressure to create fractures in the rock. Fracturing the formation may be used to accomplish by a number of different methods. Methods that permit the fracturing of multiple production zones within a wellbore during a single trip into the wellbore may be beneficial to minimize the completion time and/or costs.
For example, U.S. Pat. No. 6,006,838 entitled “Apparatus and Method for Stimulating Multiple Production Zones in a Wellbore,” which in its entirety is incorporated by reference herein, discloses a fracturing string, or work string, that includes a plurality of modules with sliding sleeves that may be used to stimulate multiple production zones in a wellbore in a single trip into the wellbore. U.S. Pat. No. 7,681,645 entitled “System and Method for Stimulating Multiple Production Zones in a Wellbore,” which in its entirety is incorporated by referenced herein, discloses positioning the fracturing string disclosed in U.S. Pat. No. 6,006,838 within a desired location within a wellbore and then cementing the fracturing string in place using an acid soluble cement. Cement is pumped down the string, out the end of the string, and up and around the outside of the diameter of the string. The cement is allowed to cure, thus cementing the fracturing string at the desired location. Sliding sleeves on each module within the fracturing string may be selectively opened to fracture desired zones within the wellbore, as detailed below.
A wiper plug may be pumped down the string after the cement, and preferably before the displacement fluid, to wipe any residual cement from the inner diameter of the string. The wiper plug also helps to separate the acid soluble cement from acid pumped down the string after the wiper plug. At least one wiper ball may also be pumped down the string after the wiper plug. The wiper ball may be pumped down the string within a spacer fluid to help protect the wiper ball from being damaged by the acid solution. The wiper ball may help to remove any residual cement from the internal bores of the modules allowing the sliding sleeves to slide when actuated. The acid pumped within the string also prevents any residual cement from curing inside of the string.
After the cement has cured around the outside of the string, fluid is pumped down the string. The hydraulic pressure of the pumped fluid moves the sliding sleeve of the lowermost module to an open position. The acid within the string breaks down the cement that has formed outside of the fracturing string after the sliding sleeve of the module is opened. Hydraulic pressure may then fracture the formation adjacent the opened module. A proppant containing slurry may follow behind the acid to extend and support the fracture. Once the formation at the lowermost module has been fractured, an appropriately sized ball may be dropped down the string to land in the ball seat of the next lowermost module. The seated ball prevents flow to the first module and the pressure within the string will build until the sliding sleeve of the second module moves to the open position. The acid may then break down the cement adjacent to the second module outside of the fracturing string and hydraulic pressure may fracture the formation at this location. The process is repeated until the cement adjacent each module has been broken down and each of the specified zones have been fractured.
The assembly disclosed in U.S. Pat. No. 6,006,838 is used for selectively stimulating a wellbore without the use of a general packer, such as an openhole inflatable packer. This assembly is especially suited to perform a combination of matrix acidizing jobs and near wellbore erosion jobs at a number of producing zones in the wellbore in a single trip.
Prior to the assembly disclosed in U.S. Pat. No. 6,006,838 and U.S. Pat. No. 7,681,645, operators who were interested in stimulating multiple producing zones in an openhole wellbore could stimulate the zones one zone at a time by using a work string and a packer. Such a method and assembly required the operator to set an inflatable packer (or other similar apparatus) above each zone of interest to be stimulated and then, following the stimulation job, to release the packer (or packers) and trip the packer assembly to a new location where it would be reset for the next stimulation job. This procedure would be repeated for each desired zone of interest. However, because of the tripping time and the difficulty in setting and maintaining the seal in inflatable packers in openhole wellbores, such a method was both time consuming and relatively unreliable. Furthermore, openhole inflatable packers (or other similar devices) are expensive to rent or to purchase. As a result of the relative unreliability and cost of using openhole inflatable packers, such assemblies prove to be uneconomical in marginal fields such as fields in the Permian Basin region of West Texas and Eastern New Mexico.
The assembly disclosed in U.S. Pat. No. 6,006,838 and U.S. Pat. No. 7,681,645 does not require an inflatable packer and is very economical to build and maintain. Thus, an operator can use the assembly for a small incremental cost over what it costs to perform an acid job and receives the benefits of not only a matrix acidizing treatment, but can also enhance the flow in the near wellbore region by eroding away near wellbore skin damage. The assembly also allows an operator to accurately position an assembly in a wellbore to ensure that the producing zones of interest are stimulated.
The present invention is an improvement to the assembly disclosed in U.S. Pat. No. 6,006,838 and U.S. Pat. No. 7,681,645 for selectively stimulating a wellbore without the use a packer. Specifically, the disclosed ball drop apparatus and method provides more flexibility in the fracturing of the wellbore formation. The tubing run ball seat assembly of the present disclosure permits the stimulation of production zones in any practically any order after opening the hydro port and the toe of the string.
Another potential advantage of the present disclosure is that a larger number of production zones may be treated with a single trip of a work string into the wellbore. Due to the use of removable ball seat assemblies of the present disclosure, over fifty stages or modules may be treated with a single trip of a four and a half (4½) inch fracturing string.
Another potential advantage of the present disclosure is that the ball seat assemblies may be retrieved from the work string. After removal, the ball seat assemblies may be serviced and potentially reused on additional work strings. Further, the removal of the ball seat assembly from the work string permits the closure of the fracturing sleeve, if needed.
The present disclosure is directed to overcoming, or at least reducing the effects of, one or more of the issues set forth above.